Systems and Methods For Enhanced Waterfloods

ABSTRACT

Methods and systems for enhancing oil recovery from a subterranean formation comprising at least a first region and a second region are provided. An exemplary method includes creating an injection stream by adding a salt to a water stream to increase a concentration of an ion and injecting the injection stream into the subterranean formation through a first injection well in the first region of the subterranean formation. Fluid is produced from the subterranean formation and separated to generate an aqueous stream comprising at least a portion of the ion. The salt is added to the aqueous stream to adjust the concentration of the ion in the aqueous stream to a desired level. The aqueous stream is injected into the subterranean formation through a second injection well in the second region of the subterranean formation.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority benefit of U.S. Provisional ApplicationSer. No. 61/415,692 filed Nov. 19, 2010 entitled: “Systems and Methodsfor Enhanced Waterfloods using Advanced Ion Management,” and U.S.Provisional Application Ser. No. 61/432,079 filed Jan. 12, 2011entitled: “Systems and Methods for Enhanced Waterfloods,” the entiretyof which is incorporated by reference herein.

FIELD

The present disclosure relates generally to systems and methods forenhancing oil recovery using waterflood methods. More particularly, thepresent disclosure relates to systems and methods of using advanced ionmanagement to enhance conventional waterflood techniques.

BACKGROUND

This section is intended to introduce the reader to various aspects ofart, which may be associated with embodiments of the present invention.This discussion is believed to be helpful in providing the reader withinformation to facilitate a better understanding of particulartechniques of the present invention. Accordingly, it should beunderstood that these statements are to be read in this light, and notnecessarily as admissions of prior art.

Historically, there have been limited publications on the effect ofchanging ion composition for waterflooding of carbonate reservoirs. Theprocess often caused problems in carbonate reservoirs due to adversereactions between the injected water and anhydrite or gypsum which mayexist in the carbonate reservoir. See Taber, J. J., and Martin, F. D.,“Technical Screening Guides for the Enhanced Recovery of Oil”, SPE12069, presented at SPE Annual Technical Conference and Exhibition, SanFrancisco, Calif., 5-8 Oct. 1983. The trend, however, has been changingrecently due to an increased interest in enhanced waterflooding (EWF). Abetter than expected oil recovery at a fractured chalk reservoir at theEkofisk field in the North Sea has provided some motivation for thesestudies. See, e.g., Puntervold, T., Strand, S., and Austad, T.,“Coinjection of seawater and produced water to improve oil recovery fromfractured North Sea chalk oil reservoirs,” Energy and Fuels, 23,2527-2536 (2009); Strand, S., Puntervold, T., and Austad, T., “Effect oftemperature on enhanced oil recovery from mixed-wet chalk cores byspontaneous imbibition and forced displacement using seawater,” Energyand Fuels, 22, 3222-3225 (2008); Tweheyo, M. T., Zhang, P., and Austad,T., “The Effects of Temperature and Potential Determining Ions Presentin Seawater on Oil Recovery From Fractured Carbonates,” SPE 99438,SPE/DOE Symposium on Improved Oil Recovery, Tulsa, Okla., 22-26 Apr.2006; Høgnesen , E. J., Strand, S., and Austad, T., “Waterflooding ofPreferential Oil-Wet Carbonates: Oil Recovery Related to ReservoirTemperature and Brine Composition,” SPE 94166, presented at SPE EAGEAnnual Conference, Madrid, Spain, 13-16 Jun. 2005; Zhang, P., Tweheyo,M. T., and Austad, T., “Wettability alteration and improved oil recoveryin chalk: The effect of calcium in the presence of sulfate,” Energy andFuels, 20, 2056-2062 (2006); Zhang, P., Tweheyo, M. T., and Austad, T.,“Wettability alteration and improved oil recovery by spontaneousimbibition of seawater into chalk: Impact of the potential determiningions Ca²⁺, Mg²⁺, and SO₄ ²⁻,” Colloids and Surfaces, 301,199-208 (2007).These articles are generally referred to herein as “the Austad studies.”The Austad studies focused on spontaneous imbibition tests forlaboratory measurements with the goal of improving the imbibitionprocesses suitable for fractured chalk reservoirs. Sulfate anions ofvarious concentrations were added to sea water in those studies.

In addition, Ligthelm, D. L., Gronsveld, J., Hofman, J. P., Brussee, N.J., Marcelis, F., and van der Linde, H. A.: “Novel WaterfloodingStrategy by Manipulation of Injection Brine Composition,” SPE 119835,presented in EUROPEC/EAGE Conference and Exhibition, Amsterdam, TheNetherlands, 8-11 Jun. 2009 have performed spontaneous imbibitionexperiments on Middle Eastern limestone with 5% increment in oilrecovery, giving a 17% total recovery of original oil-in-place (OOIP).However, Høgnesen , E. J., Strand, S., and Austad, T.: “Waterflooding ofPreferential Oil-Wet Carbonates: Oil Recovery Related to ReservoirTemperature and Brine Composition,” SPE 94166, presented at SPE EAGEAnnual Conference, Madrid, Spain, 13-16 Jun., 2005 have observed noeffect of high sulfate brine during spontaneous imbibition onunfractured limestone treated with modified crude oil. As opposed tospontaneous imbibition studies, there have been few publications oflaboratory coreflooding studies in which the waterflood performance isenhanced by adding inorganic salts for use in unfractured carbonates,such as limestones and dolomites, among others. In one such study,Bortolotti, V., Gottardi, G., Macini, P., and Srisuriyachai, F.,“Intermittent Alkali Flooding in Vertical Carbonate Reservoir”, SPE121832, presented at the SPE EUROPEC/EAGE Annual Conference andExhibition held in Amsterdam, The Netherlands, 8-11 Jun. 2009, theauthors discussed a technique for intermittent flow of an alkalisolution for enhancing oil recovery. A concentrated alkali solution isinjected into a reservoir, and the flow is intermittently paused beforebeing resumed. The laboratory results showed a greater oil recovery thancontinuous flow without the pausing.

Previous published work has reported enhanced oil recovery by addingsulfate to the brine with chalk cores for both spontaneous imbibitionand corefloods. See Høgnesen, E. J., Strand, S., and Austad, T.:“Waterflooding of Preferential Oil-Wet Carbonates: Oil Recovery Relatedto Reservoir Temperature and Brine Composition,” SPE 94166, presented atSPE EAGE Annual Conference, Madrid, Spain, 13-16 Jun. 2005; Strand, S.,Puntervold, T., and Austad, T., “Effect of temperature on enhanced oilrecovery from mixed-wet chalk cores by spontaneous imbibition and forceddisplacement using seawater,” Energy and Fuels, 22, 3222-3225 (2008);and Puntervold, T., Strand, S., and Austad, T.: “Coinjection of seawaterand produced water to improve oil recovery from fractured North Seachalk oil reservoirs,” Energy and Fuels, 23, 2527-2536 (2009). Otherstudies have examined spontaneous imbibition in limestone cores. SeeLigthelm, D. L., Gronsveld, J., Hofman, J. P., Brussee, N. J., Marcelis,F., and van der Linde, H. A., “Novel Waterflooding Strategy byManipulation of Injection Brine Composition,” SPE 119835, presented inEUROPEC/EAGE Conference and Exhibition, Amsterdam, The Netherlands, 8-11Jun. 2009.

In contrast, a number of studies have focused on ion changes in concertwith surfactant or polymer injection into reservoirs. For example, inBortolotti, V., Macini, P., and Srisuriyachai, F., “LaboratoryEvaluation of Alkali and Alkali-Surfactant-Polymer Flooding Combinedwith Intermittent Flow in Carbonate Rocks”, SPE 122499, presented at theSPE Asia Pacific Oil and Gas Conference and Exhibition held in Jakarta,Indonesia, 4-6 Aug. 2009, the authors combined analkali-surfactant-polymer flood with the intermittent or paused flowdiscussed previously. One set of results indicated that high alkaliconcentration, e.g., greater than about 0.5 molar alkali is notrecommended, due to the formation of in-situ produced soap. Another setof results indicated that the highest final recovery may be obtained byinjecting a surfactant, intermittently flowing an alkali solutionthrough the reservoir, then flooding the reservoir with a polymersolution.

U.S. Patent Publication No. 2008/0011475 by Berger, et al. discloses anoil recovery method that uses amphoteric surfactants. The method isperformed by injecting into an aqueous solution containing a mixture ofamphoteric surfactants into one or more injection wells. The amphotericsurfactants have a hydrocarbyl chain length between 8 and 26, and somedegree of unsaturation. Oil is recovered from one or more producingwells. The aqueous solution can also contain a thickening agent, analkali, or a co-solvent.

International Patent Application Publication No. WO 2005/106192, byAustad, discloses a method for displacing petroleum from a carbonaterock. In the disclosed method, a positive electrical potential of thecarbonate is reduced. This is performed by injecting a fluid thatsupplies negatively charged ions. As a result, the degree of recovery ofpetroleum is enhanced.

International Patent Application Publication No. WO 2008/029131, byCollins, et al., discloses a method for hydrocarbon recovery bywaterflooding of a subterranean formation. The aqueous injection mediumcomprises a water soluble organic compound that contains an oxygen ornitrogen atom.

U.S. Pat. No. 4,074,755 to Hill, et al., discloses a waterflood processfor recovering oil that is chemically aided and controlled by an ionexchange. The process involves successively injecting a chemical slugcontaining an active aqueous surfactant system or a thickened aqueousliquid, followed by an aqueous liquid into a reservoir. Generally thereservoir selected will have a significant amount of ion exchangecapacity. The ionic composition of each injected fluid is adjusted toprovide a ratio between the concentration of its effectively predominatemonovalent cation and the square root of the concentration of itseffectively predominate divalent cation. The ratio is selected tosubstantially match the ratio in the aqueous fluid immediately ahead ofthe injected fluid.

U.S. Pat. No. 4,714,113 to Mohnot, et al., discloses a technique forenhanced oil recovery using alkaline water flooding with a precipitationinhibitor. The waterflood injection fluid includes an alkali and awater-soluble precipitation inhibitor that can prevent divalent cationsfrom precipitating. Beyond the immediate vicinity of the injection well,the permeability characteristics of the reservoir are modified byprecipitation of divalent metal hydroxides or divalent metal carbonates.

U.S. Pat. No. 4,466,892 to Chan, et al., discloses a method for causticflooding of a reservoir using a stabilized water. The stabilizer is alignosulfonate material that is blended with the injection water beforethe addition of an alkaline chemical. The lignosulfonate prevents theformation of precipitates due to hydroxides.

U.S. Pat. No. 4,828,031 to Davis discloses a method for recovering oilfrom diatomite. In the method, a solvent is injected into a diatomitefollowed by an aqueous surfactant solution. The solution contains adiatomite/oil water wettability improving agent and an oil/water surfacetension lowering agent.

U.S. Patent Application Publication No. 2007/0215351 by Wernli, et al.,discloses the use of phosphorus and nitrogen containing formulations insecondary oil recovery operations. The phosphorous and nitrogen isgenerally in the form of ions, such as phosphate and ammonium ions,among others.

Many of the studies discussed above, however, focused on sand-basedreservoirs and not carbonates. More recently, there have been a fewstudies investigating the effect of injecting low salinity water incarbonates. For example, Yousef, A. A., Al-Saleh, S, Al-Kaabi, A., andAl-Jawfi, M., “Laboratory Investigation of Novel Oil Recovery Method forCarbonate Reservoirs,” SPE 137634, presented at Canadian UnconventionalResources and International Petroleum Conference, Calgary, Canada, 19-21Oct. 2010 investigated the effect of using diluted sea water asinjection water in Middle East limestone cores. Significant uplifts,e.g., 18 to 19% OOIP additional oil recovery, have been measured andattributed to low salinity effects the study.

Alotaibi, M. B., Nasralla, R. A., and Nasr-El-Din, H. A., “WettabilityChallenges in Carbonate Reservoirs,” SPE 129972, presented at SPEImproved Oil Recovery Symposium, Tulsa, Okla. 24-28 Apr. 2010, alsostudied salinity effects in Middle East limestone cores in corefloods,but reported inconclusive results.

Bagci, S., Mustafa, V. K., and Turksoy, U. “Effect of brine compositionand alkali flood in the permeability damage of limestone reservoirs,”SPE 65394, presented at SPE International Symposium on OilfieldChemistry, Houston, Tex., 13-16 Feb. 2001, studied the effect of brinesalinity on oil recovery in unconsolidated limestone packs with Garzancrude oil. Bagci, et al., studied waterflood performance of variousconcentrations and combinations of KCl, NaCl, and CaCl2 brine. Nodefinite low salinity effect was observed for unfractured limestones inthat study. On the other hand, it has been known for over 50 yearsinjecting low salinity water can have positive effects for some clasticreservoirs.

The improved oil recovery from varied waterflooding experiments has beenattributed to a number of possible fundamental mechanisms. One leadingtheory, proposes that wettability alteration towards water-wet conditionis the dominating mechanism for uplift in oil recovery for enhancedwaterflood in carbonates. For example, in Webb, K. J., Black, C. J. J.,and Tjetland, G., “A laboratory study investigating methods forimproving oil recovery in carbonates” SPE 10506-MS, presented at theInternational Petroleum Technology Conference, 21-23 Doha, Qatar,November 2005, the authors presented capillary pressure curves measuredduring waterflood experiments on Valhall reservoir limestone cores atreservoir conditions. They observed that water-wetting characteristicsof the studied rock increased after flooding with brine containingsulfate. They noted that sulfate was initially absent in both formationbrine and the secondary injection brine. The increase in water-wetnesswas manifested as an increase in the positive part of the capillarypressure curve. In addition, in the Austad studies, in their work withchalk/limestone over the last ten years, the increased oil recovery incarbonate rock has been attributed to wettability alteration towardswater-wetness.

While waterflooding has been used to enhance oil recovery, significantportions of the original oil in place is still left in the reservoirafter conventional waterflooding techniques. Accordingly, the needexists for improved systems and methods of waterflooding a reservoir torecover still greater portions of the original oil in place. It will beeasily understood that while increasing the percentage recovery by even1-2% of the original oil in place (OOIP) may seem small in terms ofpercentages, the incremental improvement is significant both in terms ofthe improvement over the conventional techniques and in the improvementto the economies of a hydrocarbon recovery operation.

Further information may be found in at least in Hallenbeck, L. D.,Sylte, J. E., Ebbs, D. J., and Thomas, L. K., “Implementation of theEkofisk Field Waterflood,” SPE Formulation Evaluation, 6, 284-290(1991); Lager, A., Webb, K. J., Black, C. J. J, Singleton, M., andSorbie, K. S., “Low Salinity Oil Recovery—An ExperimentalInvestigation,” presented at the International Symposium of the Societyof Core Analysis, Trondheim, Norway, 12-16 Sep. 2006; Sylte, J. E.,Hallenbeck, L. D., and Thomas, L. K., “Ekofisk Formation PilotWaterflood,” SPE 18276, presented at SPE Annual Technical Conference andExhibition, Houston, Tex., 2-5 Oct. 1988; Taber, J. J. and Martin, F.D., “Technical Screening Guides for the Enhanced Recovery of Oil”, SPE12069, presented at SPE Annual Technical Conference and Exhibition, SanFrancisco Calif., 5-8 Oct. 1983; Verma, S., Adibhatla, B., Leahy-Dios,A., Willingham, T., “Modeling Improved Recovery Methods in anUnstructured Grid Simulator”, presented at the International PetroleumTechnology Conference, Doha, Qatar, 7-9 Dec. 2009.

SUMMARY

An embodiment provides a method for enhancing oil recovery from asubterranean formation comprising at least a first region and a secondregion. The method includes creating an injection stream by adding asalt to a water stream to increase a concentration of an ion andinjecting the injection stream into the subterranean formation through afirst injection well in the first region of the subterranean formation.Fluid is produced from the subterranean formation and separated togenerate an aqueous stream comprising at least a portion of the ion. Thesalt is added to the aqueous stream to adjust the concentration of theion in the aqueous stream to a desired level. The aqueous stream isinjected into the subterranean formation through a second injection wellin the second region of the subterranean formation.

A number of measurements may be performed as part of the method. Thesalt and a concentration adjustment may be determined by performing oildisplacement tests in porous media on at least two ion concentrations ofan aqueous displacement fluid. The ion concentration of the producedaqueous stream to determine a required adjustment to obtain the desiredlevel.

Other techniques may be used with the method. For example, the methodmay include adding a first salt to a first aqueous stream to form afirst injection stream and adding a second salt to a second aqueousstream to form a second injection stream, injecting the first injectionstream into the subterranean formation at a first time, and injectingthe second injection stream into the subterranean formation at a secondtime.

The injection stream may have some similar properties. The kinematicviscosity of the second injection stream may be within about 30% of thefirst injection stream at a common temperature and shear rate. Further,the interfacial tension of the second injection stream may be within afactor of three of the first injection stream as measured against ahydrocarbon at the same temperature.

The injection streams may be formed in a number of ways. A concentrationof an ion may be adjusted to be at least 2,000 ppm different between thefirst injection stream and the second injection stream. The same saltmay be selected for the first salt and the second salt. A mothersolution, in which the ion is present in a high concentration, may bemade. The concentration of the ion in the mother solution may be greaterthan about 5,000 ppm. The concentration of the ion in the aqueous streammay be adjusted by adding a selected amount of the mother solution tothe aqueous stream. The mother solution may be used to adjust theconcentration of the ion prior to injecting the aqueous stream into thesecond region. The ion may be selected from borate, phosphate, nitrate,silicate, carbonate, acetate, citrate, sulfate, or any combinationsthereof. A phosphate may added in a concentration that is greater thanabout 1,000 ppm and less than about 10,000 ppm. A borate may be added ina concentration that is greater than about 5,000 ppm and less than about22,500 ppm or in a concentration that is greater than about 5,000 ppmand less than about 13,500 ppm.

The salt may be mixed with the injection stream in a number of ways. Theinjection stream may be created by adding a solid salt of the ion to theinjection stream and flowing the injection stream through a staticmixer. The injection stream may be created by adding a solid salt of theion to the injection stream and mixing the injection stream in acontinuous stirred reactor. A solid salt of the ion may be blended withthe injection stream in a batch process. Further, a solid salt of theion may be blended into the injection stream in a distribution system,wherein the distribution system carries the injection stream to aninjection well.

The amount of the injection stream used may be related to the porevolume of the reservoir. The aqueous stream may be injected into aregion of the subterranean formation in an amount that ranges from 0.1to 2 times the pore volume of the region of the subterranean formation.The injection volume may be 0.2 to 0.7 times the pore volume of theregion of the subterranean formation. The pore volume of a region may bedetermined from changes in an ion concentration during the waterfloodstage of production. The pore volume of a region may be determined usinga reservoir simulation.

Another embodiment provides a system for enhancing oil recovery from asubterranean formation. The system includes a first injection streamformed by adding a salt to a first aqueous stream to increase aconcentration of an ion and an injection system configured to inject thefirst injection stream into a first subterranean formation through afirst injection well. A production well is configured to produce fluidfrom the subterranean well. A fluid separation system configured toseparate the fluid produced from the subterranean formation into atleast two fluid streams, wherein a first fluid stream comprises a secondaqueous stream including at least a portion of the ion. An ionadjustment system is configured to adjust an ion concentration in thesecond aqueous stream to form a second injection stream. A secondinjection system is configured to inject the second injection streaminto a second region of the subterranean formation.

The system may include various other devices to perform relatedfunctions. For example, a measurement system configured to determine aconcentration of an ion in the second injection stream may be included.The system may include an auger configured to add a solid saltcomprising the ion to the second aqueous stream. A static mixer may beconfigured to mix the solid salt with the second aqueous stream. Anauger may also be configured to add a solid salt comprising the ion tothe first or second aqueous stream and a static mixer may be configuredto mix the solid salt with the first or second aqueous stream. Acontinuous stirred tank reactor may be configured to mix the first orsecond aqueous stream with a solid salt containing the ion. A batchmixer may be configured to mix the first or the second aqueous streamwith a solid salt containing the ion.

The ion may include borate, phosphate, nitrate, silicate, carbonate,acetate, citrate, sulfate, or any combinations thereof. The phosphatemay be added in a concentration that is greater than about 1,000 ppm andless than about 10,000 ppm. The borate may be added in a concentrationthat is greater than about 5,000 ppm and less than about 22,500 ppm orin a concentration that is greater than about 5,000 ppm and less thanabout 13,500 ppm.

The system may include a number of injection wells and production wellsacross the subterranean formation, wherein the injection wells and theproduction wells are configured to access different zones of thesubterranean formation. An average subterranean formation temperaturemay be greater than about 130° F. (about 54° C.).

DESCRIPTION OF THE DRAWINGS

The advantages of the present techniques are better understood byreferring to the following detailed description and the attacheddrawings, in which:

FIG. 1 is a schematic diagram of a waterflood process that may be usedto increase oil production from a reservoir;

FIG. 2 is a block diagram of a waterflood process;

FIG. 3 is a diagram of one pattern of wells that can be used toimplement a waterflood process for a region in a reservoir;

FIG. 4 is a block diagram of a staged waterflood process;

FIG. 5 is a diagram of a reservoir showing a pattern of wells that canbe used to implement a staged waterflood process;

FIG. 6 is a method for performing a waterflood process using asequential injection of ions;

FIG. 7 is a method for performing a staged waterflood process;

FIG. 8 is a method for performing a waterflood process using ionreplacement;

FIG. 9 is schematic representation of a coreflooding apparatus used inthe experiments described herein;

FIG. 10 is a plot of incremental oil recovery and pressure drop for coreD1;

FIG. 11(A) is a CT scan image of a dolomite core (D1);

FIG. 11(B) is a CT scan image of a limestone core (L2);

FIG. 12 is a plot of incremental oil recovery and pressure drop for coreD2;

FIG. 13 is a plot of incremental oil recovery and pressure drop forlimestone core L1;

FIG. 14 is a plot of incremental oil recovery and pressure drop forlimestone core L2 using a borate waterflood;

FIG. 15 is a plot of incremental oil recovery and pressure drop forlimestone core L3 using a phosphate waterflood;

FIG. 16 is a plot of incremental oil recovery and pressure drop for corelimestone L4 using seawater without added ions as the waterfloodmaterial;

FIG. 17 is a plot of oil recovery and ion chromatography results forlimestone core L4 using seawater as the waterflood material;

FIG. 18 is a plot of incremental oil recovery and pressure drop forlimestone core L5 using phosphate ions in the waterflooding;

FIG. 19 is a plot of incremental oil recovery for limestone core L6;

FIG. 20 is a plot showing further examples of oil recovery from aphosphate modified waterflood and a borate modified waterflood;

FIG. 21 is a plot showing incremental oil recovery due to addition ofinorganic salts to the injection brine;

FIG. 22 is a plot showing incremental oil production after a drop in thetotal dissolved solids (TDS) of the flood water from 180,000 ppm (partsper million on a mass basis) to sea water condition (SW w/o sulfate);

FIG. 23 is a plot showing incremental oil recovery and pressure dropafter replacement of at least a portion of the divalent ions in theformation brine with monovalent ions; and

FIG. 24 is a plot of incremental oil recovery using borate ions in thewaterflood.

FIG. 25 is a plot of the imbibition capillary pressure (Pc) as afunction of formation water saturation.

DETAILED DESCRIPTION

In the following detailed description section, specific embodiments ofthe present techniques are described. However, to the extent that thefollowing description is specific to a particular embodiment or aparticular use of the present techniques, this is intended to be forexemplary purposes only and simply provides a description of theexemplary embodiments. Accordingly, the techniques are not limited tothe specific embodiments described below, but rather, include allalternatives, modifications, and equivalents falling within the truespirit and scope of the appended claims.

At the outset, for ease of reference, certain terms used in thisapplication and their meanings as used in this context are set forth. Tothe extent a term used herein is not defined below, it should be giventhe broadest definition persons in the pertinent art have given thatterm as reflected in at least one printed publication or issued patent.Further, the present techniques are not limited by the usage of theterms shown below, as all equivalents, synonyms, new developments, andterms or techniques that serve the same or a similar purpose areconsidered to be within the scope of the present claims.

A “hydrocarbon” is an organic compound that primarily includes theelements hydrogen and carbon although nitrogen, sulfur, oxygen, metals,or any number of other elements may be present in small amounts. As usedherein, hydrocarbons generally refer to organic materials that areharvested from hydrocarbon containing sub-surface rock layers, termedreservoirs. For example, natural gas is a hydrocarbon.

“Interfacial tension” is a measurement of the surface energy present atan interface between two liquid phases that exhibit a phase boundary,such as an aqueous phase and a hydrocarbon phase. A high interfacialtension value (e.g., greater than about 10 dynes/cm) may indicate theinability of one fluid to mix with a second fluid to form a fluidemulsion. Interfacial tension may be measured at a known or fixedtemperature and pressure using any number of techniques and systems knowin the art, including, for example, spinning drop tensiometers, pendentdrop techniques, and the like. Comparisons described herein weremeasured using a pendent drop method at the same pressure andtemperature conditions, e.g., at reservoir conditions of about 30-90°C., or higher, and 1-4 atms, or higher.

The term “natural gas” refers to a multi-component gas obtained from acrude oil well (associated gas) or from a subterranean gas-bearingformation (non-associated gas). The composition and pressure of naturalgas can vary significantly. A typical natural gas stream containsmethane (C₁) as a significant component. Raw natural gas will alsotypically contain ethane (C₂), higher molecular weight hydrocarbons, oneor more acid gases (such as carbon dioxide, hydrogen sulfide, carbonylsulfide, carbon disulfide, and mercaptans), and minor amounts ofcontaminants such as water, nitrogen, iron sulfide, wax, and crude oil.As used herein, natural gas includes gas resulting from theregasification of a liquefied natural gas, which has been purified toremove contaminates, such as water, acid gases, and most of the highermolecular weight hydrocarbons.

“Pore volume” refers to the swept volume between an injection well and aproduction well and may be readily determined by methods known to theperson skilled in the art. Such methods include modeling studies.However, the pore volume may also be determined by passing a highsalinity water, including a tracer, through the formation from theinjection well to the production well. The swept volume is the volumeswept by the displacement fluid averaged over all flow paths between theinjection well and production well. This may be determined withreference to the first temporal moment of the tracer distribution in theproduced high salinity water, as would be well known to the personskilled in the art.

“Pressure” is the force exerted per unit area by a fluid, includinghydrocarbon, water or mixtures, on the walls of a volume. Pressure canbe shown as pounds per square inch (psi). “Atmospheric pressure” refersto the local pressure of the air. “Absolute pressure” (psia) refers tothe sum of the atmospheric pressure (14.7 psia at standard conditions)plus the gage pressure (psig). “Gauge pressure” (psig) refers to thepressure measured by a gauge, which indicates only the pressureexceeding the local atmospheric pressure (i.e., a gauge pressure of 0psig corresponds to an absolute pressure of 14.7 psia). The term “vaporpressure” has the usual thermodynamic meaning. For a pure component inan enclosed system at a given pressure, the component vapor pressure isessentially equal to the total pressure in the system.

A “subterranean formation” and/or “subsurface formation” means asubsurface region, regardless of size, comprising an aggregation ofsubsurface sedimentary, metamorphic, and/or igneous matter, whetherconsolidated or unconsolidated, and other subsurface matter, whether ina solid, semi-solid, liquid, and/or gaseous state, related to thegeological development of the subsurface region. A formation may containnumerous geologic strata of different ages, textures, and mineralogiccompositions. A subterranean formation may include a subterranean, orsubsurface, reservoir that includes oil or other gaseous or liquidhydrocarbons, water, or other fluids. A subterranean formation mayinclude, but not limited to geothermal reservoirs, petroleum reservoirs,sequestering reservoirs, and the like.

A “salt” is an “ionic compound derived from a variety of organic andinorganic counter ions well known in the art. The ions may include suchcations as sodium, potassium, calcium, magnesium, ammonium,tetraalkylammonium, and the like. The salts may also such anions asborate, phosphate, silicate, nitrate, carbonate, citrate, acetate,sulfate, and the like.

“Substantial” when used in reference to a quantity or amount of amaterial, or a specific characteristic thereof, refers to an amount thatis sufficient to provide an effect that the material or characteristicwas intended to provide. The exact degree of deviation allowable may insome cases depend on the specific context.

Overview

Embodiments described herein provide methods and systems for enhancingoil production through control of ion concentrations in waterfloodsolutions. The methods, referred to herein as Advanced Ion Management(AIM) techniques, are implemented by selectively adding or removing ionsfrom injection brines to enhance oil recovery compared to formationbrines, e.g., connate water. In some embodiments, the techniques can usesequential injections of solutions having different ions or differentconcentrations of ions. In various embodiments, a staged enhancement maybe used in which ions recovered with produced fluids from one region ofa reservoir are used to form injection solutions for other regions ofthe reservoir. In another embodiment, at least a portion of divalent ormultivalent ions can be replaced with monovalent ions prior to injectionof the resulting fluid. These techniques can be combined in variousaspects of the AIM techniques depending on the properties of theparticular fields. For example, a produced connate water may be treatedto replace a portion of the divalent ions with monovalent ions. Othersalts may be mixed in to form different solutions for sequentialinjection, and the produced fluids may be used in other regions of areservoir. As discussed below, tests of oil recovery from experimentalcores were performed as different ions were added or removed from thewaterflooding brine. The results of the waterflooding with differentions was compared and used to develop systems and methods for optimizingthe enhancement of the oil recovery. Without being bound by presentlyheld theories, it is currently believed that the fluids and compositionsof the AIM techniques can enhance oil recovery through one or more ofthe following mechanisms: partial rock dissolution; surface ionexchange; and in-situ generation of surfactants. The techniquesdisclosed herein may function at any temperatures, but may operate moreefficiently at temperatures greater than about 100° F. (about 38° C.),e.g., as found in many reservoirs

As discussed below, the AIM techniques may be implemented in many waysin field operation, which may depend on a variety of factors, such asthe geochemistry of the formation and the chemistry of the availablewater supplies. To assist in understanding the extent and scope of thepresent AIM techniques, examples of waterflooding and systems that maybe used in waterflooding are discussed with respect to FIGS. 1-5.Examples of methods that may be used to implement the techniques arediscussed with respect to FIGS. 6-8. FIGS. 9-23 present experimentaltechniques used to demonstrate some of the concepts embodied in the AIMsystems and methods.

FIG. 1 is a schematic diagram of a waterflood process 100 that may beused to increase oil production from a reservoir. In the schematic 100,a reservoir 102 may be accessed by an injection well 104 and aproduction well 106. Although shown as vertical wellbores, it will beclear that any configuration of vertical and horizontal wellbores may beused. The reservoir is a subsurface formation that can containhydrocarbons. Injection fluid, such as an aqueous solution of ions, maybe injected through the injection well 104, for example, from a pumpingstation 108 at the surface 110. At the same time, production fluids 112,such as a hydrocarbons and aqueous solutions, are harvested from thereservoir 102, for example, through another pumping station 114. Theproduction fluids 112 may be processed in a facility 116 to separateaqueous fluids from the hydrocarbons 118. The hydrocarbons 118 can besent to other facilities for refining or further processing. The aqueousfluids may be mixed with make-up salts, and the resulting injectionsolution 120, may then be reinjected into the reservoir 102. Theinjection well and production wells are not limited to single lines tothe reservoir 102, but may include multiple wells.

FIG. 2 is a block diagram of a waterflood process 200. In the waterfloodprocess 200, a production well 202 is used to access a reservoir region204. The produced fluids 206 may be flowed through a separator 208 toseparate hydrocarbons 210 from aqueous fluids 212. The separator 208 mayinclude, for example, a settling tank, a large pressurized verticalvessel, or a large drum designed to separate fluid phases (e.g., oil,gas, and aqueous) based on differences in density. The aqueous fluid 212may flow through an ion adjustment system 214, in which ionconcentrations may be adjusted by removing ions, replacing ions,precipitating ions, or adding ions. The ion adjustment system 214 mayinclude an ion exchange resin, a precipitator, a flocculation tank, aforward osmosis unit, a reverse osmosis unit, a solids feeder to addsalts, mixed bed reactors, ion exchange membranes, and the like. The ionadjustment system 214 may also include an ion analysis system, such asan ion chromatography unit, an electrochemical detector, and the like,as discussed below. The resulting solution 216 may be added to aninjection solution mixer 218. In an embodiment, the total dissolvedsolids (TDS) of the water can be decreased, for example, by mixing theinjection water with a lower salinity source water, such as aquiferwater, lake water, stream water, catchment water, or water from othersources of fresh or lower salinity water. The lower salinity water canalso be obtained by decreasing the salinity by using reverse osmosis orforward osmosis.

In an embodiment, the hardness of the water, e.g., the concentration ofmultivalent ions, such as calcium, magnesium, manganese and iron, can bedecreased by using an ion exchange resin to replace the multivalent ionswith hydrogen, sodium, or potassium. The hardness may also be decreasedby precipitating the hard water ions out of solution by adding a saltthat contains silicates, carbonates or similar anion which can remove Caand Mg from solution through precipitation. In an embodiment, the ratioof the ions can be changed to promote oil recovery. Specifically, thecalcium and magnesium ratios can be changed to cause additional oilrecovery.

In the injection solution mixer 218, a solid salt or a mother solution220, for example, a concentrated solution of a salt, may be added toadjust the concentration of an ion and prepare an injection solution220. The injection solution 220 may then be injected to the formation204 through an injection well 224. The injection solution 220 may bemixed with a stream 226 of feed water 228 at the well head 230 or in atrunk line or distribution line leading to the well head, for example,using a static mixer. In some embodiments, the mother solution 220 mayalso be blended with the feed water stream 226 at the well head 230 orin a trunk line or distribution line leading to the well head, forexample, using a static mixer.

The mother solution 220 may be formulated by mixing an ion source 232,such as a solid salt or salt slurry, with another stream 234 of feedwater 228 in a second mixer 236. Either of the injection solution mixer218 and the second mixer 236 may be a batch tank mixer, a continuousstirred tank reactor, or a solid salt feed located upstream of a staticmixer.

To obtain the correct solution concentration, a number of feedbackmechanisms can be used to ensure that the desired salt concentration isobtained and maintained. One process includes taking periodic samplesfrom the flow stream, either from the mother solution 220 or theinjection solution 222, at one or more points along the flow process.Various embodiments may include sampling the concentration at the mixers218 and 236, from the distribution system, at the well head 230, or fromwithin the well 224. The measurements can then be used to adjust ionconcentrations to ensure that targeted concentrations are achieved andmaintained. Measurements could be either automated or manual, and coulduse an inline or stand alone detector to measure conductivity, salt/ionconcentration, pH, density, absorbance, scattering, NMR, radioactiveadsorption, radioactive emission, temperature or other measurementprocess to provide feedback on the concentration or quality of thesolution. The solution concentration could then be controlled, forexample, by changing the mixing rate or solution concentration.

There are several possible processes that may occur as a result of asalt being added to the displacing fluid which may help in liberatingcrude oil during a flood. Specifically, the salts can react with thefatty or natural acids in the crude oil to form in-situ surfactants. Incrude oils, reactions with carboxylic and naphthenic acids areconsidered the primary source for in-situ surfactant generation. Thesurfactants may be generated at the interface between the oil and thedisplacing fluid, and can cause a reduction in the interfacial tension(IFT). The surfactant can also lead to a change in the wetabilitybetween the oil and the rock substrate which may also contribute toenhanced recovery and the liberation of crude oil.

The latter process has been described as a “rolling up” of the oil dueto the in-situ surfactant causing the oil to less favorably wet thesurface. Through the addition of a salt or salts, it is also possible tochange the surface charge or zeta potential of the rock substratetowards a more neutral or negative state. This then results in areduction in the attraction between the crude oil and rock substrate.There can also be a direct competition between the polar compounds inthe crude oil, e.g., carboxylic acids or naphthenic acids, among others,and the anions that are added to the displacing fluid as part of thesalt. This direct competition can result in crude oil being desorbedfrom the surface. Further, it is possible to promote dissolution of thecarbonate material, for example, by changing the ion composition, suchas by adding specific salts, by decreasing the total dissolved solidsconcentration, by decreasing the hardness of the water, or by changingthe relative ion concentrations. The dissolution may result inadditional oil being desorbed from the surface and hence allowingincreased recovery. While the above mechanisms describe some of theprocesses that may occur, they in no way represent all the process thatoccur, or limit the scope of the invention in any way. It will be clearthat the waterflood process is not limited to a single injection well224 and a single production well 202, but can often be implemented usinga number of wells configured to access a region of the reservoir.

FIG. 3 is a diagram of one pattern 300 of wells 302 and 304 that can beused to implement a waterflood process for a region in a reservoir. Inthe pattern 300, injection wells 302 may be interspersed with productionwells 304 so that a region 306 of the reservoir is provided with enoughwells to access the region 306. Although the pattern 300 shown isregular, it will be clear that uneven patterns may be used as needed toreach a region of a reservoir. The techniques may be used across morethan one region of a reservoir, for example, with separated aqueousfluids containing injected ions recycled to other regions of the field,with our without adjusting the ion concentration.

FIG. 4 is a block diagram of a staged waterflood process 400. In FIG. 4,like numbered units are as described with respect to FIG. 2. In FIG. 4,a first injection well 402 and a first production well 404 are completedto a first region 406 of a reservoir. The injection well 402 is used toinject a waterflood or injection solution 220 into the first region 406.Fluids 206 are produced from the first region 406 through the productionwell 404. As discussed with respect to FIG. 2, the produced fluids 206are passed to a separator 408 which separates the fluids 206 intohydrocarbons 210 and an aqueous fluid 212.

A second region 410 of the reservoir may be accessed by a secondproduction well 412, which may be used to produce fluid 414 from thesecond region 410. The fluid 414 from the second region 410 may bepassed to the same separator 408, or to another separator, forseparation of the hydrocarbons 210 from the aqueous fluid 212. Theaqueous fluid 212 from the first region 406 and the second region 410may be processed in an ion adjustment system 214 to remove or replaceions, to analyze concentrations for adjustment, or both. The resultingsolution 216 can be sent a mixer 218 in which a mother solution 220 canbe used to increase a concentration of one or more ions. The ionadjusted solution 416 may then be injected back into the second region410 through a second injection well 418. As discussed with respect toFIG. 2, the injected solution 416 may be mixed with a stream 226 of feedwater 228, at the well head 420, in the mixer 218, or in thedistribution system leading to the well head 420. As the aqueous stream212 has been recovered, at least in part, after injection into the firstregion 406, this may allow lower costs by capturing and recycling ionsfrom the previously injected brine for use in the second region 410 ofthe reservoir. The production and injection is not limited to the numberof wells shown, but may include any number of wells used to efficientlyaccess the regions of the reservoir, as discussed with respect to FIG.5.

FIG. 5 is a diagram of a reservoir 500 showing a pattern of wells 502and 504 that can be used to implement a staged waterflood process. Afirst region 506 of the reservoir 500 is accessed by a first set ofinjection wells 502 and production wells 504. A second region 508 of thereservoir 500 is accessed by a second set of injection wells 502 andproduction wells 504. As discussed with respect to FIG. 4, fluidsproduced from the first region 506 and the second region 508 can beseparated into hydrocarbons and aqueous fluid. The aqueous fluid maycontain at least a portion of the ions injected into the first region506. The concentrations of the ions in the aqueous fluid may be adjustedto match selected targets, and the aqueous fluid can be injected intothe second region 508 through the injection wells 502 in the secondregion 508. Any number of other regions may be treated this way. Forexample, the produced fluid from the second region 508 may be used totreat other regions 510 of the reservoir 500. Any number of methods mayutilize the systems above to implement advanced ion management (AIM) forwaterflooding reservoirs to enhance oil production, such as thosediscussed with respect to FIGS. 6-8.

FIG. 6 is a method 600 for performing a waterflood process using asequential injection of ions. The method 600 begins at block 602 withthe formation of a first injection stream by adding an ion to an aqueousstream. The first injection stream may be made using fresh water, saltwater, connate water, or any combinations thereof. A salt can be mixedwith the water to add the target ions. The salts can include such anionsas borate, silicate, nitrate, carbonate, citrate, acetate, phosphate, orsulfate, or any combinations thereof. Generally, the cations will bemonovalent, such as ions of sodium, lithium, and the like, to lower thechance of precipitation.

In field applications, as noted above, the salt can be added to theinjection fluid in a number of ways including, but not limited to, bydissolution of the salt using a mixer to create a concentrated “mothersolution.” The mother solution can be mixed with a more dilute solutionto create the desired brine concentration prior to injecting into thereservoir.

Variations on mixing the mother solution with the injection fluid mayinclude passing the mother solution and the injection fluid through astatic mixer prior to injecting into a well or wells. Further, themother solution may be injected directly into a well along with theinjection fluid, where the two solutions may mix within the well bore.The mother solution and the injection fluid may be mixed in adistribution system connecting a facility to one or more injectionwells. For example, the mother solution can be injected into a trunkline of the distribution system, allowing mixing within the distributionsystem and well bore. An augur feed system that dispenses the mothersolution at a predetermined rate may be incorporated into any of theabove mixing systems.

The injection stream may be mixed to a desired concentration, either inbatch or in a continuous flow process. Here the salt can be mixed withthe injection fluid using mixers, a baffled system, or a system wherethe salt is allowed to dissolve into the aqueous phase to reach thedesired aqueous concentration. Concentrations that may be used for thevarious ions are discussed with respect to the examples, below.Injections streams may also be formed by reducing an ion concentration.

At block 604, a second injection stream may be formed with substantiallythe same viscosity and interfacial tension as the first injectionstream. Substantially the same viscosity indicates a kinematic viscosityvalue that is within about a factor of 3, or within a factor of 1.5, ata reservoir temperature and shear rate characteristic of flow throughthe bulk of the reservoir (e.g., 1 s⁻¹). Such substantially similarviscosities are characteristic of fluids only differing in salinity andgenerally not those with added polymer viscosifiers. Comparisons areperformed at common pressures, temperatures, and shear conditions,preferably those characteristic of conditions experienced within theformation of interest. Substantially the same interfacial tensionindicates a value between an aqueous phase and a liquid hydrocarbonphase that is within about three times to five times or within one orderof magnitude. For the solutions discussed herein, such similar valueswill result in little, if any, effect on the spontaneous formation ofoil and water emulsions. The liquid hydrocarbon phase may include oilrecovered from the formation of interest. Comparisons are performed atcommon pressures and temperatures, such as those characteristic ofconditions experienced within the formation of interest. The differencesin the viscosity and surface tension discussed above are likely toosmall to have any effect on flow properties and, thus, any differencesin oil recovery are likely to be more influenced by ion concentration,identity, and changes.

The second injection stream may be formed using the same materials andmixing techniques as the first injection stream. The concentration of anion in either injection stream may be set to at least about 1 gram ofion per liter of solution. The ions selected for the second injectionmay be the same as the first stream, or may be different. Theconcentrations of the ions added to the first and second injectionstreams may differ by about 2000 ppm or more. Further, in the firstinjection stream, a concentration of a first added ion may be greaterthan about 1000 ppm higher than the concentration of the same ion in thesecond injection stream. Similarly, the concentration on an ion added tothe second injection stream may be set to greater than about 1000 ppmhigher than the concentration of the same ion in the first injectionstream. The pH of the first injection stream and the second injectionstream may be the same or may be adjusted to be different. For example,the pH of one of the injection streams may be controlled to at least onepH point different from the other stream. The formation of either thefirst or the second stream may include reducing the ion concentration inanother aqueous stream, such as the source stream. The first injectionstream and the second injection stream may be formed by splitting aformation water stream into two or more portions and individually addingions to each portion.

At block 606, the first injection stream can be injected into asubterranean formation, for example, into a reservoir, into a water legbelow the reservoir, or a watered out zone of the reservoir (e.g.,residual oil zone or zone that has already been water flooded). At block608, the second injection stream can be injected into the samesubterranean formation at a different time, for example, to sequentiallycontact the same formation as the first injection stream. The secondinjection stream may be injected through the same wellbore as the firstinjection stream, or may be injected into a different wellbore. Eitherof the injection streams may be injected into the subterranean formationin an amount that ranges from 0.1 to 2 times the pore volume (PV) of thesubterranean formation. As used herein, the term “subterraneanformation” may refer to a subregion of an oil-containing reservoir, forexample, a subregion of areal extent defined by a polygon whose verticescorrespond to the location of wells.

The pore volume of a subterranean formation is equal to total volumeminus the volume occupied by rock. To calculate the PV for a region, onewould take the total pore volume bound by that region, minus the volumeoccupied by rock within that region. For example, referring to FIG. 5,the PV of region 508 would be the total PV bound by region 508 minus therock volume within region 508. To calculate the total PV for asubterranean formation consisting of several regions, one can sum thePVs for each region within the subterranean formation.

The techniques are not limited to only two sequential injections, butmay include any number of sequential injections. For example, a thirdinjection stream may be injected after the second injection stream. Thethird injection stream may differ from the second injection stream inthe same ways that the second injection stream differs from the firstinjection stream, e.g., in ion concentration, total ion concentration,pH and the like. The third and subsequent injection streams may havesubstantially the same viscosity and interfacial tension as the firsttwo injection streams. Further, the third injection stream may be thesame as the first injection streams, for example, if the injection werealternating between two injection streams. The injection does not haveto be performed into a same area or region in the reservoir. As notedabove, fluid produced from one region of a reservoir may be injectedinto another area of a reservoir, as discussed with respect to FIG. 7.

FIG. 7 is a method 700 for performing a staged waterflood process. Themethod begins at block 702 with the creation of an injection stream.This may be performed using similar materials and methods as theinjection streams discussed with respect to FIG. 6. At block 704, theinjection stream can be injected into a first region of a subterraneanformation. At block 706, a fluid may be produced from the subterraneanformation. At block 708, the fluid may be separated to produce anaqueous stream that includes at least a portion of the ions initiallyinjected. The ion concentration in the fluid may be measured asdescribed herein, and at block 710, adjusted to a desired level, forexample, by adding, removing, or replacing ions. At block 712, theaqueous stream is injected through a second injection well into a secondregion of the subterranean formation. The first region and the secondregion may or may not be in fluid communication. The staged waterfloodprocess may be used in concert with the methods described with respectto FIG. 6 or 8.

FIG. 8 is a method 800 for performing a waterflood process using ionreplacement. The method 800 begins at block 802, wherein a fluidproduced from a subterranean formation is separated to form a firstfluid stream comprising an aqueous stream. At block 804, at least aportion of divalent ions in the first fluid stream are replaced, forexample, with monovalent ions, to form a second fluid stream. Thedivalent ions may include cations, such as calcium and magnesium, amongothers, which may be replaced, for example, by flowing the first fluidstream through an ion exchange resin. As discussed with respect to FIG.6, the second fluid stream may have substantially the same viscosity andinterfacial tension as the first fluid stream. After the ionreplacement, the second fluid stream may have a total concentration ofions greater than about 100,000 ppm (parts per million on a mass basis).As used herein, the term “total concentration of ions” is equivalent tothe total dissolved solids as determined by the ratio of mass remainingafter evaporating the water within an aqueous sample and the originalmass of the sample; for example, see ASTM Standard D5907 “Standard TestMethods for Filterable Matter (Total Dissolved Solids) and NonfilterableMatter (Total Suspended Solids) in Water.” Alternatively, the totaldissolved solids can be calculated by summing the concentrations of theindividual ions found in solution where the individual ionconcentrations are measured using standard analysis methods such as ionchromatography or inductively coupled plasma. For example, see ASTMStandard D5673-10 “Standard Test Method for Elements in Water byInductively Coupled Plasma—Mass Spectrometry.” At block 806, the secondfluid stream may be injected into the subterranean formation, throughthe same well bore or through a different wellbore. The ion replacementprocess may be used in concert with the methods described with respectto FIG. 6 or 7.

EXAMPLES

A series of core flood experiments were performed to test the AIMtechnology and demonstrate that the technology disclosed herein mayyield a significant increase in oil recovery compared to waterfloodingusing formation brines. To compare the uplift potential of the AIMtechnology with the current state-of-the-art approaches, theenhancements in oil recovery using AIM technology were compared to theincremental recoveries obtained using controls containing sulfate ionsor low salinity concentrations.

Summary of Results

For the case of sulfate, incremental recoveries were obtained thatranged from 5-9% additional removal of the original oil-in-place (OOIP)over waterflood recoveries using formation brine. The effect of lowsalinity flooding was also tested by injecting sea water followingformation water. Sea water was able to increase the oil recovery by anadditional 7-9%, comparable to what has been reported previously. Forcomparison, a significant amount of oil was also recovered usingformation water that had calcium and magnesium ions selectively removed,e.g., replaced with monovalent ions. A series of tests also demonstratedthat low salinity water may not be necessary to promote enhancedrecovery in carbonates and that most of the benefit can be obtained byusing softened water, even in cases where the total dissolved solids(TDS) of the softened water was as high as 180,000 ppm.

To further expand on the effect of specific anions on enhanced oilrecovery, a series of tailored brines were tested which were able tofurther enhance recovery beyond the levels obtained using sulfate, lowsalinity or softened water. In the tests using sulfate, oil recoveryincreased by around 5-9% OOIP. However, by changing the anion in thesalt used in the modified injection brine from sulfate to borate, afurther increase in incremental oil recovery, to over 15%, was measured.The effectiveness of incrementally increasing the borate concentrationthrough a series of steps was also tested, and total recovery fromincrementally increasing the concentration was similar (within 4%) tothe recovery from increasing the salt concentration in a single step.Additional tests using phosphate further demonstrated that incrementalrecoveries could be pushed to over 20% OOIP, indicating that AIM has thepotential to significantly enhance oil recovery.

This study shows that by tailoring the ion composition of the injectionwater, significant enhancements in oil recovery can be achieved. The AIMtechnology provides significant incremental recovery, even beyond thelevels that can be obtained from the current state-of-the-art processes.Rigorously testing the process under field temperatures and pressuresusing Middle Eastern crude and core samples demonstrate the potentialfor enhanced oil recovery using AIM. Further, simulation technology canaccurately capture the recoveries and pressure drop measured in the coreflood experiments, suggesting simulations may provide a tool that can beused to accurately assess field-scale recoveries.

Experimental Details

Limestone and dolomite cores were used in this work. The limestone coreswere obtained from a Middle Eastern reservoir, while the dolomite coreswere obtained from an outcrop corresponding to a West Texas reservoir.Cores with consistent petrophysical properties were selected based onX-ray Computerized Tomography (CT), thin section petrography, androutine core analysis. All cores used in this work were 1.5 inches indiameter and about 2 inches in length. Table 1 shows the list ofselected cores and their petrophysical properties. Cores D1 and D2 hadsubstantial dolomite content, as indicated by Table 2, and had higherpermeability and initial water saturation as compared to limestonecores.

TABLE 1 comparison of core properties Pore Perme- Core Volume PorositySwi ability ID. Source Connate Brine (mL) (%) (% PV) (md) D1 West FWw/SO₄ ²⁻ 8.6 20.40 27.3 109.21 Texas D2 West Modified 10.58 19.00 31.680.33 Texas Formation Water L1 Middle FW w/SO₄ ²⁻ 14.50 25.26 10.8 6.73East L2 Middle FW w/SO₄ ²⁻ 14.27 24.85 9.5 6.79 East L3 Middle FW w/SO₄²⁻ 14.35 25.13 10.9 6.39 East L4 Middle FW w/SO₄ ²⁻ 10.73 20.05 16.32.89 East L5 Middle FW w/SO₄ ²⁻ 10.39 20.32 20.2 2.69 East L6 Middle FWw/SO₄ ²⁻ 9.06 20.61 14.6 9.53 East

Table 2 shows X-ray diffraction analysis of the selected cores.Limestone cores consisted of more than 99% calcite, while dolomite coreswere nearly 82% dolomitized.

TABLE 2 Core TALC ILLITE + ID. QUARTZ CALCITE DOLOMITE PYRITE (claysize) KAOLINITE CHLORITE SMECTITE SUM D1, D2 1.9 16.4 81.6 0.0 0.0 TR0.0 TR 99.9 L1, L2, L3 0.3 99.2 0.5 0.0 0.0 0.0 0.0 0.0 100.0 L4, L5, L60.3 99.6 0.0 TR 0.0 0.0 0.0 0.0 99.9

Oil from a Middle Eastern reservoir was used for all experiments. Table3 shows the oil properties for the tests. The total acid number measuredby ASTM D-664 and non-aqueous phase titration was found to be 0.11 mgKOH/g. Degassed (dead) oil was used in all experiments. The viscositywas estimated based on the equations of Kestin et al., “Tables of thedynamic and kinematic viscosity of aqueous NaCI solutions in thetemperature range 20-150 C. and the pressure range 0.1-35 MPa”, J. Phys.Chem. Ref. Data, Vol. 10, No. 1 (1981). All brines were synthetic, i.e.,prepared in the laboratory. Table 4 shows the formulation of variousbrines used in this work.

TABLE 3 Temperature Pressure Viscosity Density Acid Number (° F.) (psi)(cp) (g/cc) (mg KOH/g) 72 14.7 5.92 0.843 0.11 250 4000 1.13 0.797

As used herein, formation water may be referred to as “FW”, sea water as“SW,” sea water with sulfate ion selectively removed as “SW w/o SO₄ ²⁻,”sea water containing four times the usual sulfate ion concentration as“Sea water 4× SO₄ ²⁻,” formation water with calcium and magnesiumselectively omitted as “FW without Ca and Mg,” formation water withcalcium selectively omitted as “FW without Ca,” and formation watercontaining sulfate ion as “FW w/SO₄ ²⁻”. Brine can be classified eitheras modified brine or as base or formation brine. Modified brine refersto a brine which can potentially enhance oil recovery and is injectedafter base brine or after another modified brine. In all experiments,formation water is used as the base brine. Modified brines were preparedby selectively adding or omitting components from formation water or seawater compositions.

TABLE 4 Brine Compositions (ppm) Formation Water with Modified SeawaterFW Ionic sulfate Formation Formation Seawater without sulfate Seawaterwithout FW species (FW w/SO₄ ²⁻) Water (FW) Water (SW) (SW w/o SO₄ ²⁻)4× SO₄ ²⁻ Ca and Mg without Ca Na 51820 51820 22828 10345 9245 1034572591 70166 Ca 15992 15992 15992 521 521 521 0 0 Mg 1282 1282 1282 10941094 1094 0 1282 K 0 0 0 391 391 391 0 0 Cl 111516 111717 49274 1871918719 11911 111852 111852 HCO₃ 391 391 172 0 0 0 391 391 SO₄ 272 0 2722305 0 9222 0 0 TDS 181273 181202 89820 33375 29970 33484 184834 183691

FIG. 9 is schematic representation of a coreflooding apparatus 900 usedin the experiments described herein. The majority of the apparatus 900was enclosed within an oven 902 controlled at the temperature of areservoir. Floating-piston cells were used to supply dead crude oil 904,a first modified brine 906, a formation brine 908, and a second modifiedbrine 910. The floating-piston cells were driven by a hydraulic fluid(water) 912 from constant-pressure pumps 914 outside the enclosure. Thebrines were supplied to high-accuracy positive-displacement pumps, pump#1 916 and pump #2 918 for delivery to the core 920 through an oil/brineinlet valve 922. Each pump 916 and 918 comprises a pair of cylinderswhich can work together to deliver fluid indefinitely. Various bypassports 924 enabled flushing and charging of lines upon fluid changeover.A back pressure regulator (BPR) 926 was used to control fluid productionfrom the core 920.

The core 920 was mounted in a coreholder 928 which applies triaxialconfining pressure using elastic end members and a rubber sleevesurrounded by a hydraulic fluid (refined oil) 930 provided by ahydraulic pump 932. Absolute pressure was measured at both ends of thecore 920 by pressure transducers 934. The difference between theabsolute pressures provided the pressure drop across the core 920. Thecore orientation was initially horizontal, but subsequent experimentsused vertical flow, upward. Produced liquid was collected in anautomated sample collection system 936 for oil recovery and for brineion analysis. Selected aqueous samples were analyzed by ionchromatography. The pH of the injected brine and selected effluent wasalso measured. After a coreflood was complete, the core 920 was cleanedby Dean-Stark extraction and a material balance was performed on theoil.

Each core 920 was cleaned with solvents and dried. After measuringroutine properties such as porosity and permeability, the core wassaturated with formation brine 908 and centrifuged to obtain the desiredinitial water saturation. Dead crude oil (crude oil without dissolvedgas) 904 was then flowed into the core 920, and the core was 920 aged areservoir temperature for at least six weeks to restore wettabilitytoward reservoir conditions. Before a coreflood, dead crude oil 904 wasflowed through the core 920 to measure oil permeability at initial watersaturation.

Each coreflood began with a conventional waterflood of formation brine908, which may also be termed formation water, herein. Beforeestablishing pressure communication of injection brine with the core andbefore switching brine compositions, a system of pressure transducers934 and valves 938 was used to match the brine delivery pressure to thepore pressure of the core 920, in order to avoid pressure disturbancescausing flow. The typical brine injection rate was 0.1 cc/min. Afterinjecting formation brine 908, the brine was switched to a modifiedbrine 906, and the coreflood was continued. Depending on the particularexperiment, the injected brine was switched again, for example, to asecond or subsequent modified brine 910 or back to the formation brine908. Additional brine solutions could be introduced by replacing thematerial in the modified brine cylinder 908 or the second modified brinecylinder 910.

In all experiments, formation brine 908 was injected first until oilproduction ceased followed by one or many modified brines. Thus,formation brine 908 set the baseline oil recovery to compare performanceof modified brines 906 and 910 injected into the same core at a latertime. While the experimental set-up is at laboratory scale rather thanfield scale, the relative differences between waterflood compositions isexpected to be representative of the order of magnitude of the impactthe varying compositions would have when implemented in actualhydrocarbon recovery operations.

FIG. 10 is a plot 1000 of incremental oil recovery and pressure drop forcore D1. In this plot 1000, the x-axis 1002 represents the volume ofmaterial injected as a multiple of the pore volume of the core plug. Theleft y-axis 1004 represented the oil recovered from the core as aproportion of the original oil-in-place (OOIP). The right y-axis 1006represents the pressure drop across the core, as measured by thepressure difference between the inlet and outlet measurements.

The experiment was performed at 158° F. and 300 psi pore pressure (1200psi net confining pressure) with the coreholder oriented horizontally.Sea water 4× SO₄ ²⁻ was used as the modified brine. An increment of 6%OOIP recovery 1008 was obtained with sea water 4× SO₄ ²⁻ after core D1was flooded with formation water. Switching between the brines, asindicated at line 1010, reduced the pressure drop 1012 across core D1.Additional oil recovery (higher water saturation) and lower brineviscosity contributed to this change. Both the formation water and thesea water 4× SO₄ ²⁻ were clear solutions at the experimental conditions.

Oil recovery 1008 with formation water alone was 30.3% OOIP, which wassignificantly lower than the expected range of oil recovery. Further,oil trickled out of the core for many pore volumes. Core heterogeneitywas suspected to be one of the causes for this delayed oil recoverybehavior. Accordingly, computer assisted tomography scans were run onexample cores to determine heterogeneity, as discussed with respect toFIGS. 11(A) and (B).

FIG. 11 a is a CT scan image of dolomite (D1) and FIG. 11(B) is a CTscan image of limestone (L2). The CT scan images are collectivelyidentifies by the reference number 1100. As illustrated in FIG. 11(A),the West Texas dolomite core has significant heterogeneity, while thelimestone core shown in FIG. 11(B) is relatively homogeneous. To reducethe effect of heterogeneity on oil recovery, the coreholder orientationwas changed from horizontal to vertical for future experiments wherebrine was injected at the bottom. The changed orientation was expectedto make the brine front gravity stable and to decrease heterogeneityeffects. A second dolomite coreflood was performed on core D2 invertical orientation with the same brine sequence and experimentalconditions as used for core D1, as discussed with respect to FIG. 12.

FIG. 12 is a plot 1200 of incremental oil recovery 1202 and pressuredrop 1204 for core D2. The axes 1002, 1004, and 1006 are as defined withrespect to FIG. 10. Connate brine for core D2 was modified formationwater. Changing the coreholder orientation improved oil recovery 1202with formation water. The oil recovery 1202 with formation water for thecore in the vertical position was 61.6% compared to 30.3% for the corein the horizontal position. Both the oil recovery profile 1202 and thepressure drop profile 1204 were sharper than those obtained for core inthe horizontal position (FIG. 10). An additional 9% OOIP was recoveredwith sea water 4× SO₄ ²⁻, which confirms repeatability and effectivenessof the sulfate ion in improving waterflood oil recovery from dolomitizedrock. Coreflood results with core D1 and D2 are summarized in Table 5.The results summarized in Table 5 and in FIGS. 10 and 12 demonstrate thepresent AIM techniques are effective with dolomite cores.

TABLE 5 Pressure Orientation Formation AIM Core Temperature Pore/Sleeve(Horizontal/ Water Recovery Modified Recovery ID (° F.) (psi) Vertical)(OOIP) brine (OOIP) D1 158 300/1500 Horizontal 30.3% Sea Water 6% 4× SO₄²⁻ D2 158 300/1500 Vertical 61.6% Sea Water 9% 4× SO₄ ²⁻

FIG. 13 is a plot 1300 of incremental oil recovery 1302 and pressuredrop 1304 for limestone core L1. The axes 1002, 1004, and 1006 are asdefined above (FIG. 10). All experiments with Middle Eastern limestonewere performed at 250° F. and 4000 psi, using a 1000 psi net confiningpressure, and in a vertical orientation. Similar to dolomite cores, acoreflood was performed on core L1 to evaluate the effectiveness ofsulfate in improving waterflood recovery from limestone. However atlimestone coreflood conditions, anhydrite precipitation with sea water4× SO₄ ²⁻ was predicted. Geochemist's Workbench® (GWB) was used toestimate brine stability. Previous studies have reported no additionaloil recovery with artificial sea water containing three times sulfateconcentration during spontaneous imbibition experiment on a MiddleEastern limestone at 248° F. The poor brine performance was attributedto solubility problems caused by anhydrite precipitation. Hence, amodified version of sea water 4× SO₄ ²⁻ was used for core L1 thatcontained extra MgCl₂ sufficient to minimize anhydrite precipitation. Asshown in the plot 1300, formation water recovered 55.8% OOIP and wasfollowed by sea water 4× SO₄ ²⁻ containing extra MgCl₂, which recoveredan additional 5.1% OOIP. The formation water injection rate was 0.1cc/min, but the initial injection rate of modified sea water 4× SO₄ ²⁻was less than 0.1 cc/min. However, the injected rate of modified seawater 4× SO₄ ²⁻ was raised to the formation water injection rate. Thisreduced initial flow rate is reflected in the pressure drop 1304 in FIG.13. However, the decreased initial flow rate is not believed to haveimpacted the performance of modified sea water 4× SO₄ ²⁻.

After establishing AIM effectiveness with sulfate ions for dolomite andlimestone cores, the experimental efforts were expanded to identifyother commercially available salts that may improve waterflood oilrecovery. Several salts were tested on Middle Eastern limestone, asdiscussed herein. Among those that performed well are borate andphosphate.

FIG. 14 is a plot 1400 of incremental oil recovery 1402 and pressuredrop 1404 for limestone core L2 using a borate waterflood. The axes1002, 1004, and 1006 are as defined above (FIG. 10). Formation waterrecovered 57.7% OOIP before oil production ceased. Formation water wasinjected for about 10 pore volumes. The pressure drop data for theinitial part of this coreflood was not available. Modified brinecontaining borate ions was flooded through core L2 after formationwater. The modified borate brine contained 22.5 g borax (Na₂B₄O₇.10H₂O)in 1 kg solution of SW w/o SO₄ ²⁻. For comparison and consistency withthe previous corefloods, sea water was used as the base for modifiedbrine preparation. However, sulfate ion was selectively removed from thesea water to separate its contribution to any enhanced oil recovery.Incremental oil recovery 1402 of 15.6% OOIP was measured with SW w/o SO₄²⁻ containing borate salt. Most of this enhanced recovery occurred inthe injection interval of about one pore volume as shown in FIG. 6.Enhanced oil recovery was significantly higher for the modified brinecontaining borate ion than for the modified brine containing sulfateion. Similar to previous corefloods, pressure 1404 across core L2dropped while switching between injection brines, which may beattributed to the same reasons, an increase in water saturation due toadditional oil recovery, and lower modified brine viscosity.

FIG. 15 is a plot 1500 of incremental oil recovery 1502 and pressuredrop 1504 for limestone core L3 using a phosphate waterflood. The axes1002, 1004, and 1006 are as defined above (FIG. 10). Similar to thecoreflood on core L2, the modified brine concentration of 10 g trisodiumphosphate in 1 kg solution of SW w/o SO42− was prepared by adding a saltcontaining phosphate into SW w/o SO₄ ²⁻. Formation water recovered 48.3%OOIP in about eight pore volumes and was followed by the modified brine.An additional 21.3% OOIP was recovered with SW w/o SO₄ ²⁻ containingphosphate salt. Enhanced oil recovery occurred with sharp pressure dropacross core L3 with most of the enhanced oil recovery occurring in aboutone pore volume interval of modified brine injection. Corefloodexperiments performed on Middle Eastern limestone for salt screening aresummarized in Table 6. For the AIM experiments performed on MiddleEastern limestone, modified brines containing phosphate and borate saltswere more effective than with sulfate salt.

TABLE 6 Pressure Orientation Formation AIM Core Temperature Pore/Sleeve(Horizontal/ Water Recovery Recovery ID (° F.) (psi) Vertical) (OOIP)Modified brine (OOIP) L1 250 4000/5000 Vertical 55.8% Sea Water 4× 5.1%SO₄ ²⁻ (with extra MgCl2) L2 250 4000/5000 Vertical 57.7% SW w/o SO₄²⁻ + 15.6% Borate L3 250 4000/5000 Vertical 48.3% SW w/o SO₄ ²⁻ + 21.3%Phosphate

In all plots, a noticeable delay in the pressure drop profile appearsafter switching from formation to modified brine. This delay occurredbecause of the volume required to replace the relatively large deadvolume from the pump to the core inlet in the test apparatus 900 (FIG.9), as compared to core pore volume. A similar delay was observed foroil recovery, which occurred due to the dead volumes present bothupstream and downstream of the core. The upstream dead volume was largerthan the downstream dead volume. The modified brines discussed abovehave consisted of sea water and various added salts. To evaluate theimpact of just sea water on oil recovery, coreflood experiments wereperformed using SW w/o SO₄ ²⁻ as the modified brine, as discussed withrespect to FIG. 16. Sea water has lower salinity and is a softer brinecompare to formation water.

FIG. 16 is a plot 1600 of incremental oil recovery 1602 and pressuredrop 1604 for core limestone L4 using seawater without added ions as thewaterflood material. The axes 1002, 1004, and 1006 are as defined above(FIG. 10). Formation water recovered 64.4% OOIP in about 11 porevolumes. SW w/o SO₄ ²⁻ containing no additional salt alone recovered anadditional 9% OOIP.

FIG. 17 is a plot 1700 of oil recovery 1702 and ion chromatographyresults 1704-1710 for limestone core L4 using seawater as the waterfloodmaterial. The x-axis 1002 and the left y-axis 1004 are as defined above(FIG. 10). The right y-axis 1703 represents the ion concentration ofsodium 1704, calcium 1706, magnesium 1708, and potassium 1710, asdetermined by an ion chromatograph. The concentration of each of theions changed sharply with switching between brines, unlike the oilrecovery 1702 which was sluggish, with oil trickling out of the core formany pore volumes. Stabilized values were close to the ion concentrationin sea water. The concentrations of ions of magnesium 1708, potassium1710, and sodium 1704 stabilized in less pore volumes compared to theconcentration of calcium 1706 during brine switching. The calcium ionwas the most sluggish and took about two pore volume to stabilize. Thiscan be attributed to strong calcium contrast of 16 to one betweenformation water and sea water. Any small mixing between the two brinescan reflect strongly on calcium concentration profile. The possibilityof rock dissolution in small quantity cannot be ruled out as well.

A coreflood experiment was designed to compare the effectiveness of seawater alone versus sea water containing a salt in enhancing oil recoveryfrom the studied Middle Eastern rock-oil system. Phosphate was selectedas the salt added to sea water to prepare the modified brine in thisexperiment. This experiment was also designed to determine the effectiveconcentration range required to observe significant enhanced oilrecovery with phosphate. The experiment was performed on core L5, asdiscussed with respect to FIG. 18.

FIG. 18 is a plot 1800 of incremental oil recovery 1802 and pressuredrop 1804 for limestone core L5 using phosphate ions in the waterflood.The axes 1002, 1004, and 1006 are as defined above (FIG. 10). The corewas first flooded with formation water followed by SW w/o SO₄ ²⁻. Thiswas then followed by three brines containing an increasing concentrationof phosphate ion dissolved in SW w/o SO₄ ²⁻ The brine containing thehighest concentration of phosphate, 10 g of trisodium phosphate in 1 kgsolution of SW w/o SO₄ ²⁻, was the same as the concentration of themodified brine used with core L3 (FIG. 15). The other two brinescontained 1/100 and 1/10 of the highest concentration phosphate brine inSW w/o SO₄ ²⁻ , i.e., 1 g of trisodium phosphate in 1 kg solution of SWw/o SO₄ ²⁻, and 0.1 g of trisodium phosphate in 1 kg solution of SW w/oSO₄ ²⁻, respectively. An additional 7.1% OOIP was recovered with SW w/oSO₄ ²⁻ after the formation waterflood, which itself produced a recoveryof 63.2% OOIP in about 11 pore volumes before oil production ceased.This recovery includes the oil that was recovered just after switchingbetween SW w/o SO₄ ²⁻ and SW w/o SO₄ ²⁻ containing 1/100 times basephosphate ion concentration. This oil was trapped during SW w/o SO₄ ²⁻flood in the BPR at the core outlet and was dislodged early during thecoreflood with 1/100 times phosphate. Similarly, the small jump in oilrecovery after formation waterflood was discounted from SW w/o SO₄ ²⁻recovery. Accordingly, this indicates that sea water alone may improvewaterflood efficiency compared to formation water in Middle Easternenvironment.

Brines containing 1/100 and 1/10 times base phosphate ion concentrationin SW w/o SO₄ ²⁻ produced minimal oil resulting in a negligible changein pressure drop 1804. However, an increase in oil recovery was observedwith the highest concentration phosphate brine, suggesting that athreshold phosphate ion concentration greater than about 1 g oftrisodium phosphate in 1 kg solution of SW w/o SO₄ ²⁻ (e.g, greater thanabout 1,000 ppm or 0.006 M) and less than about 10 g of trisodiumphosphate in 1 kg solution of SW w/o SO₄ ²⁻ (e.g, less than about 10,000ppm or 0.061 M) may be required. A corresponding decrease in pressuredrop was also noted. However, the slope of the oil recovery curve withbase phosphate brine in this core is not as sharp as with core L3 (FIG.15). Previous oil recovery by SW w/o SO₄ ²⁻ and a correspondingreduction in oil relative permeability can explain this sluggish oilrecovery behavior. Overall, a combined increment of 15.7% OOIP wasobserved with all modified brines.

Clearly, adding a selective salt to sea water may have a greater impacton the oil recovery than sea water alone. In core L4, sea watercontaining phosphate may further enhance oil recovery after sea waterinjection. Also, for this fluid/rock system, the oil recovery profilewas sharper when a salt is added to SW w/o SO₄ ²⁻ (core L2, L3 and L4)compared to just SW w/o SO₄ ²⁻. SW w/o SO₄ ²⁻ alone could recover anadditional 7-9% OOIP recovery in our system using small core plugs. Asimilar range of oil recovery on carbonates with brines of similar orlower salinity than SW w/o SO₄ ²⁻ (29970 ppm) has been reported inliterature. In experiments with carbonate composite coreflood at 212°F., Yousef, A. A., Al-Saleh, S, Al-Kaabi, A., and Al-Jawfi, M.:“Laboratory Investigation of Novel Oil Recovery Method for CarbonateReservoirs,” SPE 137634, presented at Canadian Unconventional Resourcesand International Petroleum Conference, Calgary, Canada, 19-21 Oct.2010, observed additional 7-8.5% OOIP recovery with 28800 ppm brine,which was injected after coreflooding with twice concentrated, 57600 ppmbrine. Field connate water had a salinity of 213734 ppm. See Alotaibi,M. B., Nasralla, R. A.and Nasr-El-Din, H. A.: “Wettability Challenges inCarbonate Reservoirs,” SPE 129972, presented at SPE Improved OilRecovery Symposium, Tulsa, Okla., 24-28 Apr. 2010, reported additional8.6% oil recovery with an aquifer brine (5436 ppm) after formationwaterflood (230000 ppm). While these earlier reports illustratedpotential enhanced oil recovery using waterflood compositions of lowersalinity, none of these reports disclose or suggest using a waterfloodcomposite at the same total dissolved solids, or suggest adding a salt,like borate or phosphate.

Two prominent differences between sea water and formation water are thetotal salinity and brine hardness. To potentially identify the cause ofsea water effectiveness in improving waterflood recovery, an experimentwas designed to investigate the impact of brine hardness and totalsalinity on oil recovery from Middle Eastern limestone. The experimentwas performed on core L6, which was flooded with four brines: formationwater, formation water without magnesium and calcium (FW without Mg andCa), formation water without magnesium (FW without Ca), and SW w/o SO₄²⁻. Total salinity of the first three brines was similar and close to182000 ppm. The results are discussed with respect to FIG. 19.

FIG. 19 is a plot 1900 of incremental oil recovery 1902 for limestonecore L6. The axes 1002 and 1004 are as defined above (FIG. 10). Theformation water alone recovered 57.7% OOIP in about 19 pore volumes,which was followed by the soft formation brine, which is formation brinewith both magnesium and calcium ions selectively removed (FW without Mgand Ca). An increment of 11.4% OOIP was recovered with FW without Mg andCa. Thus, a comparable improvement in oil recovery to sea water wasobtained with a higher salinity brine but with reduced hardness. Anadditional 3.9% OOIP was obtained with FW without Ca, although the oilprofile looks like a continuation of the oil trickling from the previousbrine. Less than 2% OOIP was recovered with sea water without sulfate,which was the last injected brine in core L6. In this experiment, lowersalinity brine (SW w/o SO₄ ²) could not further improve oil recovery.Thus, the effectiveness of sea water in previous experiments may havebeen driven primarily by lower divalent cation concentration (in theseawater compared to the formation water) rather than total salinity.However, for this oil-rock system, the oil recovery profile for both seawater and soft formation water was not sharp and oil continued totrickle out for many pore volumes. Clearly, the addition of borate andphosphate salt in sea water were more effective in enhancing oilrecovery, and most of the oil was recovered in about one pore volumeinterval of modified brine injection. The experimental results involvingsoft brines (cores L4, L5, and L6) are summarized in Table 7.

TABLE 7 Pressure Orientation Formation AIM Core Temperature Pore/Sleeve(Horizontal/ Water Recovery Modified recovery ID (° F.) (psi) vertical)(OOIP) Brines (OOIP) L4 250 4000/5000 Vertical 64.4% SW w/o SO₄ ²⁻ 9.0%L5 250 4000/5000 Vertical 63.2% SW w/o SO₄ ²⁻, 7.1% (SW w/o Multiple SO₄²⁻), 15.7% Dilutions of Overall Phosphate L6 250 4000/5000 Vertical57.7% FW without 11.4%, 3.9%, Ca and Mg, 1.8% FW without Ca, SW w/o SO₄²

FIG. 20 is a plot 2000 showing further examples of oil recovery from aphosphate modified waterflood 2002 and a borate modified waterflood2004. The axes 1002 and 1004 are as defined above (FIG. 10). The corewas flooded for eight pore volumes using formation water to get anaccurate assessment of recovery under a conventional waterflood.Consistent with typical laboratory core floods, the overall recovery forthe formation waterflood was around fifty percent. The waterflood wasthen switched to a modified injection brine where the inorganic salttrisodium phosphate at a concentration of about 10,000 ppm (1 wtpercent) was added to synthetic sea water. Overall oil recovery 2002using the modified injection brine increased from around fifty percentup to seventy percent, resulting in an increase of over twenty percentincremental recovery.

Also illustrated in the plot 2000 are results from a modified waterfloodusing borate 2004. This test was conducted on a core with similarproperties as the previous test. The same core was used for this test.In preparation, the limestone core was restored to an oil-wet conditionusing the aging process described herein. During the initial waterflood, overall oil recovery 2002 was around fifty seven percent afterapproximately ten pore volumes of connate water. Following the initialwaterflood, a modified brine including about 22,500 ppm (2.25 wtpercent) borax decahydrate was injected. During injection of themodified brine, oil recovery 2004 increased from around fifty sevenpercent up to around seventy five percent, resulting in an increase inincremental oil recovery of about sixteen percent.

FIG. 21 is a plot 2100 showing incremental oil recovery 2102 due toaddition of inorganic salts to the injection brine. The axes 1002 and1004 are as defined above (FIG. 10). In the plot, a formation brineinjection was followed by an injection of a modified phosphate brine,using the concentrations discussed with respect to FIG. 20, e.g., 10 gtrisodium phosphate in 1 kg solution of SW w/o SO₄ ²⁻. This was followedsequentially by a modified borate brine of the same concentration as inFIG. 20, without further conditioning of the core between solutions. Byinjecting the borate brine sequentially following the phosphate brine,an additional uplift in incremental oil recovery of around five percentwas obtained. This was followed by a modified brine consisting of bothborate and phosphate. The combined brine included about 10,000 ppmtrisodium phosphate and about 22,000 ppm borax decahydrate, which wereadded to a synthetic sea water. The final step of the flood resulted inan additional couple of percent increase in incremental oil recovery.The results from the third and fourth steps of FIG. 21 indicate that bysequentially changing ions, and combining different salts, synergies canbe obtained where the total oil recovery is higher than would beobtained for either brine alone.

FIG. 22 is a plot 2200 showing incremental oil production 2202 after adrop in the total dissolved solids (TDS) of the flood water from about180,000 ppm 2204 to sea water condition (SW w/o sulfate) 2206. The axes1002 and 1004 are as defined above (FIG. 10). In a core flood of a 1.5inch diameter 2 inch carbonate core plug, the initial injection water,which was a formation water 2204, had a total dissolved solidsconcentration of about 180,000 ppm (Formation Water, Table 4). Theinitial waterflood was then followed by a lower salinity flood of about30,000 ppm synthetic sea water 2206 (Sea Water without sulfate, Table 4)which resulted in an increase in OOIP recovered of 12%. Furthersequential ion changes 2208 continued to show improvements to recovery2202, resulting in a final recovery of over 90%.

FIG. 23 is a plot 2300 showing incremental oil recovery 2302 andpressure drop 2304 after replacement of at least a portion of thedivalent ions in the formation brine with monovalent ions. The axes1002, 1004, and 1006 are as defined above (FIG. 10). In a core flood ofa 1.5 inch diameter by 2 inch long carbonate core plug, the initialinjection water (formation water) had a total dissolved solidsconcentration of 180,000 ppm (Formation Water, Table 4). During theinitial waterflood, two different flow rates were tested and account forthe first two plateaus 2306 and 2308. Following the second plateau 2308,the injection water was replaced with a softened formation water 2310which has a composition similar to the original formation water, butwith the calcium and magnesium removed (FW without Ca and Mg, Table 4).The change in injection water from formation water (55% OOIP recovered)to softened formation water (70% OOIP recovered), resulted in anincremental recovery of 15% OOIP.

FIG. 24 is a plot 2400 of incremental oil recovery 2402 using borateions in the waterflood. The axes 1002 and 1004 are as defined above(FIG. 10). The core was first flooded with FW w/SO₄ ²⁻ followed byequilibrated SW (here, equilibrated SW refers to a synthetic SW that wasequilibrated with limestone by passing the brine through a limestonecore (not containing oil) in sequential steps, where at each step theion concentration of the brine was measured; the brine was repeatedlypassed through the limestone core until the measured ion concentrationsreached a stable value, indicating the brine had reached equilibriumwith the limestone core. The equilibration step was included to minimizethe potential of dissolution during the waterflood and hence separatethe potential effects of dissolution from the effect of adding theinorganic salts). This was then followed by three brines containing anincreasing concentration of borate ion dissolved in equilibrated SW. Thebrine containing the highest concentration of borate, 22.5 g borax(Na₂B₄O₇.10H₂O) in 1 kg solution of equilibrated SW (about 0.059 M) wasthe same as the concentration of the modified brine used in FIG. 14. Theother two brines contained 5 g borax (Na₂B₄O₇.10H₂O) in 1 kg solution ofequilibrated SW (about 0.013 M), and 13.5 g borax (Na₂B₄O₇.10H₂O) in 1kg solution of equilibrated SW (about 0.035 M).

The brine containing 5 g borax in 1 kg solution produced minimaladditional oil recovery 2402, whereas the brine containing 13.5 g boraxin 1 kg solution resulted in an additional 23% OOIP recovered 2402,suggesting that a threshold borate ion concentration greater than about5 g of borax in 1 kg solution (e.g, greater than about 5,000 ppm or0.013 M) and less than about 13.5 g of borax in 1 kg solution (e.g, lessthan about 13,500 ppm or 0.035 M) may be required.

FIG. 25 is a plot 2500 showing the imbibition capillary pressure (Pc)2502 on the y-axis as a function of formation water saturation (Sw) 2504on the x-axis, for three Middle Eastern limestone plugs: 2506, 2508 and2510. For this test, all three plugs were initially centrifuged toresidual oil saturation using formation brine (Formation Water, Table4). The centrifuge test was performed at 150° F., and the revolutionspeed was increased in steps up to 3200 rpm. After centrifuging, theplugs were separately flooded with borate brine (seawater w/osulfate+22.5 g/L of Borax) at 250° F. and 500 psi. Table 8 shows theplug properties and oil production data after centrifuge and corefloodtests.

TABLE 8 Centrifuge and coreflood results on plugs 2506, 2508 and 2510Plug 2506 2508 2510 Centrifuge Brine Formation Formation Formation WaterWater Water Oil Oil A Oil A Oil B Permeability (mD) 4.200 5.7 5.7Initial water saturation (%) 12.9 22.3 17.6 Initial oil (cc) 12.56812.768 8.297 Oil produced during centrifuge (cc) 7.00 9.00 5.50 Oilproduced during centrifuge 55.7% 70.5% 66.3% (% OOIP) Oil producedduring borate brine 0.91 1.05 0.06 flush Additional oil recovered withborate 7.2% 8.2% 0.7% brine (% OOIP)

For plugs 2506 and 2508, an additional 7-8% OOIP was obtained using theborate brine, suggesting that the modified brine was able to liberateadditional oil beyond the levels obtained using formation water. Forplug 2510, less than 1% additional oil was recovered using the modifiedborate brine. This agrees with expectations because in previouscorefloods with rock and oil systems similar to plug 2510, minimaladditional oil was recovered. The oil B used in plug 2510, had a lowertotal acid number than oil A. The capillary pressure curves in FIG. 25indicate that plug 2510 is relatively more water-wet compared to plugs2506 and 2508 and is a potential reason plug 2510 did not showsignificant incremental oil recovery.

In an additional test using a rock and oil system similar to plug 2506,both centrifuge and coreflood tests were performed with the boratebrine. As expected, minimal oil was recovered during the coreflood test.These results suggest that for plugs which have already been exposed toborate brine, re-flooding with borate brine only provides minimaladditional uplift. Conversely, for cores that have only been exposed toformation water, additional oil can be recovered by using an AIM brine,borate in this case.

Overall, these test results suggest that the modified borate brine isable to reduce residual oil saturation beyond the levels achieved usingformation water, and hence, achieve higher oil recoveries.

Summary of Results

In the work described with respect to FIGS. 10-24, experiments wereperformed on single plugs to perform quick screening of various modifiedbrines and to develop an understanding of the AIM technology. The errormargins are higher than a composite coreflood experiment due to smallerfluid volumes and a larger capillary end effect. The experiments areintended to give a recovery range and compare different modified brinesperformance. Accuracy of these experiments can be improved by performingthem on a larger composite (5-7 plugs in series). For a betterrepresentation of reservoir conditions, experiments need to be performedusing live oil.

In all experiments, formation water was injected first until oilproduction ceased. The target oil left for the modified brine was the“difficult” oil which was discontinuous and/or in the form of thin film.In a field application, a smaller pore volume of formation water may beinjected, and chances for improving recovery and forming an oil bank arehigh. Reservoir heterogeneity may impact sweep efficiency, which wouldimpact oil recovery in a field-scale application, and may reduce overallrecovery factor.

For corefloods discussed in this disclosure, the key mechanism forimproved oil recovery is believed to be wettability alteration towards awater-wet condition. While the alteration to a water-wet condition maybe the key mechanism, the experiments described herein reveal severalmanners in which this change to water-wet may be effected.

Rock dissolution may be the dominating mechanism for improved recoverywith sea water (core L4 and L5) and soft formation water (core L6). Bothbrines were soft compared to formation water, which was in chemicalequilibration with the rock before modified brine injection. Uponinjection of soft brine, rock dissolution may occur causing some oil todesorb and alter wettability towards water-wet state. Small rockdissolution could be sufficient in limestone to observe desiredwettability alteration with soft brines.

Compared to just soft injection brine, adding a salt to sea waterclearly improved modified brine performance (cores L1, L2, L3 and L5)with most of the oil recovered with one pore volume injection. Theevidence is demonstrated at least in coreflood L5 where phosphate ionadded to sea water was able to further enhance oil recovery after seawater injection. Clearly, adding salt seems to further impact therock-fluid interaction. Modified brine containing a selective salt addedto sea water may recover additional oil by both rock dissolution andsurface ion exchange. Brine softness may trigger rock dissolution, whilepresence of salt like phosphate, borate, and sulfate may induce surfaceion exchange. The relative contribution of these two mechanisms maydepend on brine composition and the type of salt added.

The process of adding a salt to sea water to enhance oil recovery asdiscussed herein is not an alkaline flooding. In an alkaline waterflood,the pH of the injection water is increased by adding a strong alkali tothe injection water. Further, an acidic crude reacts with the alkalinewater and oil to generate, in-situ, enough surfactant to reduceoil-water interfacial tension (IFT) to low values (10-2-10-4 dynes/cm).This IFT reduction increases the capillary number (viscous to capillaryforces) required to lower residual oil saturation.

In contrast, the acid number of the oil described herein was low (0.11mg KOH/g) and unfavorable for an effective alkaline flooding. Table 9shows IFT and pH for different oil-brine system.

TABLE 9 IFT and pH for different oil-brine system Brine IFT (dynes/cm)pH at 200° F. Formation Water 21 6 Sea Water 25 6.7 Phosphate salt insea water 12 8.8 Borax salt in sea water — 7.4 NaOH salt in sea water1.6 11

IFT was measured at 4000 psi and 250° F., whereas pH was measured at200° F. and atmospheric pressure. Clearly, IFT between the oil andbrines were high for an alkaline flooding. The IFT for the bestperforming modified brine, sea water containing phosphate salt, measured12 dynes/cm; while a strong alkali like sodium hydroxide could onlyreduce IFT to 1.6 dynes/cm even though brine pH at 200° F. was 11,sufficiently high for an alkaline flooding. Even for an acidic crudeoil, the pH values (as shown in Table 9) for the modified brines used inthis work were too low side for effective alkaline flooding, and werefound to further decrease with increases in temperature. Thus, thesystems and methods of the AIM technology are different than used foralkali flooding. While the AIM technology utilizes different fundamentalmechanisms and utilizes different compositions and procedures, thereremains a possibility that some in-situ surfactant generation and itsinteraction with rock and oil in the presence of inorganic salt maycontribute to altering wettability, but its contribution is minimalcompared to other factors.

In previous studies, the extent of wettability alteration was found toincrease with temperature. In those studies, a temperature above 212° F.was found to be important to observe oil recovery. To recover additionaloil with a modified brine during spontaneous imbibition, a large shiftin wettability towards water-wet state is needed such that existingpositive capillary pressure changes to a negative, or a sufficiently lowvalue where gravity force becomes dominating.

For viscous flooding, a change in capillary pressure is not required fora modified brine to be effective. A small shift in wettability towardswater-wet state may be sufficient to improve oil recovery. Therefore,the AIM technology described herein can be effective for non-fracturedcarbonates even at lower temperatures (<212° F.). Significant oil wasrecovered at 158° F. (70° C.) during coreflood experiments on core D1and D2.

Overall, the AIM technologies described herein may provide a low-costenhanced oil recovery (EOR) method that can be easy to implement. Allsalts used in this work are commercially available and are much cheaperthan surfactants. Unlike a surfactant flood, which may haveco-surfactant, alkali, polymer, alcohol or combination added to theinjection slug, AIM techniques may use just one salt that is added to awater source. Thus, the viscosity of the solutions are not used toenhance oil recovery and may be substantially the same, e.g., within anorder of magnitude of each other. Further, the AIM technologies may beas simple as selectively removing ions to prepare the injection slug.Clearly, it may provide an inexpensive and potentially effective optionfor carbonate reservoirs.

While the foregoing discussion establishes the science and fundamentalmechanics behind the concepts of the AIM technology described herein,the present disclosure further provides operational techniques adaptedto facilitate the implementation of the AIM technology in the field.Examples of such operational techniques include operations planningtools and methods and operations procedures.

For example, to gain a better understanding of the processes thatcontrol enhanced recovery from the AIM core flood experiments, a seriesof core flood simulations were performed. The magnitude and timing ofthe incremental recovery and the associated pressure changes wereaccurately captured with the simulation, suggesting that the increasedrecovery was due to modification of the wettability induced by thechanging ion composition. Using this process, the changes in wettabilitythat can be expected under enhanced waterflood conditions can bebounded, and full field incremental recoveries can be more robustlypredicted. Having shown the utility and ability of simulators to predictthe recoveries based on the composition of the waterflood fluids,production engineers will be able to use simulators to optimize plannedwaterflood operations.

For example, the geochemistry of a particular formation segment may beanalyzed through conventional techniques. The geochemistry may be inputinto an appropriate simulator together with data regarding a proposedwaterflood composition and operation (e.g., pressure, rate, temperature,etc.). The simulator may then generate predicted recovery rates.Further, the above process of predicting a recovery for a particularwaterflood operation may be repeated for multiple proposed waterfloodoperations to enable an operator to identify an optimal operation. Stillfurther, a simulator may be adapted to iteratively simulate multiplepotential waterflood compositions and operating conditions to identifyan optimal waterflood operation based on operator selected priorities(e.g., operations cost, recovery rate, etc.).

As another example of operational enhancements that may be implementedbased on the AIM technology, the injected fluids for the waterfloodoperation may be recovered and recycled. For example, the injectionwell(s) and production well(s) may be disposed such that the waterfloodis produced together with the liberated hydrocarbons. Due to the natureof the ions being added to the waterflood composition in someimplementations of the AIM technology, the ions (borates, phosphates,etc.) are substantially carried with the water rather than being lost tothe formation. As the water is separated from the oil at the surface,the ions may be concentrated for reuse in waterflood compositions.

While the present techniques of the invention may be susceptible tovarious modifications and alternative forms, the exemplary systems,methods, implementations, and embodiments discussed above have beenshown by way of example. However, it should again be understood that theinvention is not intended to be limited to the particular embodimentsdisclosed herein. Indeed, the present techniques of the invention are tocover all modifications, equivalents, and alternatives falling withinthe spirit and scope of the invention as defined by the followingappended claims.

1. A method for enhancing oil recovery from a subterranean formationcomprising at least a first region and a second region, comprising:creating an injection stream by adding a salt to a water stream toincrease a concentration of an ion; injecting the injection stream intothe subterranean formation through a first injection well in the firstregion of the subterranean formation; producing fluid from thesubterranean formation; separating the produced fluid to generate anaqueous stream comprising at least a portion of the ion; adding the saltto the aqueous stream to adjust the concentration of the ion in theaqueous stream to a desired level; and injecting the aqueous stream intothe subterranean formation through a second injection well in the secondregion of the subterranean formation.
 2. The method of claim 1, furthercomprising selecting the salt and a concentration adjustment byperforming oil displacement tests in porous media on at least two ionconcentrations of an aqueous displacement fluid.
 3. The method of claim1, comprising measuring the ion concentration of the produced aqueousstream to determine a required adjustment to obtain the desired level.4. The method of claim 1 comprising adding a first salt to a firstaqueous stream to form a first injection stream; adding a second salt toa second aqueous stream to form a second injection stream; injecting thefirst injection stream into the subterranean formation at a first time;and injecting the second injection stream into the subterraneanformation at a second time.
 5. The method of claim 4, wherein thekinematic viscosity of the second injection stream is within about 30%of the first injection stream at a common temperature and shear rate. 6.The method of claim 4, wherein the interfacial tension of the secondinjection stream is within a factor of three of the first injectionstream as measured between a hydrocarbon and the injection stream at thesame temperature.
 7. The method of claim 4, comprising adjusting aconcentration of an ion to be at least 2,000 ppm different between thefirst injection stream and the second injection stream.
 8. The method ofclaim 4, comprising selecting the same salt for the first salt and thesecond salt.
 9. The method of claim 1, comprising creating a mothersolution, in which the ion is present in a high concentration.
 10. Themethod of claim 9, wherein the concentration of the ion in the mothersolution is greater than about 5,000 ppm.
 11. The method of claim 9,wherein adjusting a concentration of the ion in the aqueous streamcomprises adding a selected amount of the mother solution to the aqueousstream.
 12. The method of claim 1, wherein a mother solution is used toadjust the concentration of the ion prior to injecting the aqueousstream into the second region.
 13. The method of claim 1, comprisingselecting the ion from borate, phosphate, nitrate, silicate, carbonate,acetate, citrate, sulfate, or any combinations thereof.
 14. The methodof claim 13 where the phosphate is added in a concentration that isgreater than about 1,000 ppm and less than about 10,000 ppm.
 15. Themethod of claim 13 where borate is added in a concentration that isgreater than about 5,000 ppm and less than about 22,500 ppm.
 16. Themethod of claim 13 where borate is added in a concentration that isgreater than about 5,000 ppm and less than about 13,500 ppm.
 17. Themethod of claim 1, comprising: creating the injection stream by adding asolid salt of the ion to the injection stream; and flowing the injectionstream through a static mixer.
 18. The method of claim 1, comprising:creating the injection stream by adding a solid salt of the ion to theinjection stream; and mixing the injection stream in a continuousstirred reactor.
 19. The method of claim 1, comprising creating theinjection stream by blending a solid salt of the ion with the injectionstream in a batch process.
 20. The method of claim 1, comprisingblending a solid salt of the ion into the injection stream in adistribution system, wherein the distribution system carries theinjection stream to an injection well.
 21. The method of claim 1,comprising injecting the injection stream into a region of thesubterranean formation in an amount that ranges from 0.1 to 2 times thepore volume of the region of the subterranean formation.
 22. The methodof claim 21, wherein an injection volume is 0.2 to 0.7 times the porevolume of the region of the subterranean formation.
 23. The method ofclaim 21, wherein the pore volume of a region is determined from changesin an ion concentration during the waterflood stage of production. 24.The method of claim 21, where the pore volume of a region is determinedusing a reservoir simulation.
 25. A system for enhancing oil recoveryfrom a subterranean formation, comprising: a first injection streamformed by adding a salt to a first aqueous stream to increase aconcentration of an ion; an injection system configured to inject thefirst injection stream into a first subterranean formation through afirst injection well; a production well configured to produce fluid fromthe subterranean formation; a fluid separation system configured toseparate the fluid produced from the subterranean formation into atleast two fluid streams, wherein a first fluid stream comprises a secondaqueous stream including at least a portion of the ion; an ionadjustment system configured to adjust an ion concentration in thesecond aqueous stream to form a second injection stream; and a secondinjection system configured to inject the second injection stream into asecond region of the subterranean formation.
 26. The system of claim 25,comprising a measurement system configured to determine a concentrationof an ion in the second injection stream.
 27. The system of claim 25,comprising an auger configured to add a solid salt comprising the ion tothe second aqueous stream.
 28. The system of claim 25, comprising astatic mixer configured to mix the solid salt with the second aqueousstream.
 29. The system of claim 25, comprising a continuous stirred tankreactor configured to mix the second aqueous stream with a solid saltcontaining the ion.
 30. The system of claim 25, comprising a batch mixerconfigured to mix the second aqueous stream with a solid salt containingthe ion.
 31. The system of claim 25, comprising an auger configured toadd a solid salt comprising the ion to the first aqueous stream.
 32. Thesystem of claim 25, comprising a static mixer configured to mix thesolid salt with the first aqueous stream.
 33. The system of claim 25,comprising a continuous stirred tank reactor configured to mix the firstaqueous stream with a solid salt containing the ion.
 34. The system ofclaim 25, comprising a batch mixer configured to mix the first aqueousstream with a solid salt.
 35. The system of claim 25, wherein the ioncomprises borate, phosphate, nitrate, silicate, carbonate, acetate,citrate, sulfate, or any combinations thereof
 36. The system of claim35, wherein the phosphate is added in a concentration that is greaterthan about 1,000 ppm and less than about 10,000 ppm.
 37. The system ofclaim 35, wherein borate is added in a concentration that is greaterthan about 5,000 ppm and less than about 22,500 ppm.
 38. The system ofclaim 35, wherein borate is added in a concentration that is greaterthan about 5,000 ppm and less than about 13,500 ppm.
 39. The system ofclaim 25, comprising a plurality of injection wells and a plurality ofproduction wells across the subterranean formation, wherein theplurality of injection wells and the plurality of production wells areconfigured to access different zones of the subterranean formation. 40.The system of claim 25, wherein an average subterranean formationtemperature is greater than about 130° F. (54° C.).